Exploration and production of deeper, lower quality oil and gas reserves has challenged refiners and gas processors with feedstocks having significantly higher sulfur content, increasing corrosion risks. Amine units for amine gas treating (also known as “gas sweetening” or “acid gas removal”) refers to a group of processes or units that use aqueous solutions of various alkylamines (commonly referred to simply as amines) for the removal of H2S and CO2 from gases. The removal is driven by either required product specification, e.g., natural gas that contains less than 4 ppm H2S, or by environmental permission requirements.
Amine units are commonly used in refineries as well as in petrochemical plants, natural gas processing plants, and other industries. The increased level of changing ratios of H2S and CO2 in the gas feedstock has significant impact on the corrosion rate and overall unit performance of amine units. Besides amine units, there are other areas with corrosion problems due to chemically absorbed gases in liquid systems. Hydroprocessing is an important process wherein sulfur and nitrogen compounds in the crude oil feed are converted to hydrogen sulfide and ammonia. As the effluent stream from the reactor cools down, the ammonia and hydrogen sulfide combine to form solid ammonium bisulfide. To reduce corrosion, wash water is introduced in the system since ammonium bisulfide is highly soluble in water, generating sour water. Corrosion in units handling the alkaline sour water containing ammonium bisulfide has been a problem for the industries for years, particularly in Reactor Effluent Air Coolers (REAC) and adjacent pipings.
Outside the oil & gas industries, in other industries such as the food and pharmaceutical industries, there are corrosion issues due to the materials being handled, e.g., chlorinated water, beer (a weak acid), etc., particularly with the vaporization of the chemically absorbed gases in the liquid being handled in the systems such as CO2 and chlorine. Corrosion due to the presence and release of SO2, NO2, CO2, etc. is an issue in steam generation operations. Plant economics are negatively impacted by the loss of revenue due to unplanned corrosion caused plant outages, shutdown to repair impacted equipment, and repair cost due to the corrosion damage.
Methods and systems have been developed to predict and/or evaluate corrosivity impact on amine units. Predict®-Amine model is a software tool that models corrosion rates in rich amine systems based on parameters including acid loadings (H2S and CO2), heat stable amine salt (HSAS) concentration, flow velocity/shear stress, and operating temperature. Another model is a modified TSWEET® computer model from Bryan Research and Engineering that predicts corrosion when the H2S content in the amine solution is less than a pre-determined minimum value; or the gas phase H2S content is less than 5%.
Methods and systems in the prior art can dramatically under-predict corrosion rate. There is still a need for improved methods to evaluate corrosivity due to chemically absorbed gases in liquid systems, e.g., corrosion in amine units, taking into account the effect of acid gas flashing on localized corrosion, allowing for the optimization of plant operations.